U.S. patent number 8,528,643 [Application Number 13/614,556] was granted by the patent office on 2013-09-10 for wellbore laser operations.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Loyd E. East, Billy Wilson McDaniel, Roger L. Schultz, Neal Gregory Skinner, Mohamed Y. Soliman, Harold G. Walters. Invention is credited to Loyd E. East, Billy Wilson McDaniel, Roger L. Schultz, Neal Gregory Skinner, Mohamed Y. Soliman, Harold G. Walters.
United States Patent |
8,528,643 |
Schultz , et al. |
September 10, 2013 |
**Please see images for:
( Certificate of Correction ) ** |
Wellbore laser operations
Abstract
Methods, systems, and devices related to downhole wellbore
operations such as drilling and completing wells in an earth
formation include a laser device. For example, a method may include
characterizing a subterranean formation, selecting an orientation
of an aperture based on characteristics of the subterranean
formation, and using a laser to form an aperture of the selected
orientation in the wall of the wellbore.
Inventors: |
Schultz; Roger L. (Ninnekah,
OK), East; Loyd E. (Houston, TX), Walters; Harold G.
(Duncan, OK), McDaniel; Billy Wilson (Duncan, OK),
Soliman; Mohamed Y. (Cypress, TX), Skinner; Neal Gregory
(Lewisville, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Schultz; Roger L.
East; Loyd E.
Walters; Harold G.
McDaniel; Billy Wilson
Soliman; Mohamed Y.
Skinner; Neal Gregory |
Ninnekah
Houston
Duncan
Duncan
Cypress
Lewisville |
OK
TX
OK
OK
TX
TX |
US
US
US
US
US
US |
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|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
43379462 |
Appl.
No.: |
13/614,556 |
Filed: |
September 13, 2012 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20130008656 A1 |
Jan 10, 2013 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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12825906 |
Jun 29, 2010 |
8464794 |
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61221418 |
Jun 29, 2009 |
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Current U.S.
Class: |
166/297; 175/15;
175/11; 166/250.1; 166/55.1 |
Current CPC
Class: |
E21B
29/02 (20130101); E21B 43/11 (20130101); E21B
43/12 (20130101); E21B 29/06 (20130101); B33Y
70/00 (20141201); B33Y 80/00 (20141201) |
Current International
Class: |
E21B
43/11 (20060101); E21B 43/119 (20060101); E21B
7/14 (20060101) |
Field of
Search: |
;166/297,250.1
;175/11,15 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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EP |
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09072738 |
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Mar 1997 |
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JP |
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WO 97/49893 |
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Dec 1997 |
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WO |
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WO 98/50673 |
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Nov 1998 |
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WO |
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WO 02/057805 |
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Jul 2002 |
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WO |
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WO 2004/009958 |
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Jan 2004 |
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WO |
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WO 2006/008155 |
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Jan 2006 |
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WO |
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WO 2006/054079 |
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May 2006 |
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WO |
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|
Primary Examiner: Gay; Jennifer H
Attorney, Agent or Firm: Wustenberg; John W. Fish &
Richardson P.C.
Parent Case Text
CLAIM OF PRIORITY
This U.S. patent application is a continuation application under 35
U.S.C. .sctn.120 of U.S. patent application Ser. No. 12/825,806,
filed Jun. 29, 2010, now U.S. Pat. No. 8,464,794, which claims
priority under 35 U.S.C. .sctn.119(e) to U.S. Provisional
Application 61/221,418, filed on Jun. 29, 2009, the disclosure of
both being considered part of the disclosure of this application
and are hereby incorporated by reference in their entirety.
Claims
What is claimed is:
1. A method of producing fluids from a well, the well having an
existing production profile and a specified production profile, the
method comprising: if the existing production profile does not
match specified production profile, receiving location information
on apertures selected to achieve the specified production profile;
running a laser tool into a wellbore of the well; and operating the
laser tool to change a flow distribution of the wellbore to cause
the existing production profile to more closely match the specified
production profile; wherein operating the laser tool to change the
flow distribution in the wellbore comprises sealing apertures in
the wellbore using the laser.
2. The method of claim 1, wherein operating the laser tool to
change the flow distribution of the wellbore comprises forming
apertures in the wellbore using the laser.
3. The method of claim 2, wherein forming apertures in the wellbore
using the laser comprises selecting an aperture geometry to filter
solids from fluid from a subterranean zone around the wellbore, the
aperture size selected based on a distribution of sizes of
particles in the subterranean zone; and using a laser to form slots
with the selected aperture geometry in a casing installed in the
wellbore in the subterranean zone.
4. The method of claim 3, wherein selecting the aperture geometry
to filter particles from fluid in the subterranean zone comprises
selecting the aperture geometry to control sand production
including formation fines.
5. The method of claim 1, wherein changing the flow distribution of
the wellbore comprises balancing flow along a substantially
horizontal wellbore by changing the distribution of apertures along
a substantially horizontal wellbore.
6. The method of claim 1, wherein changing the production profile
of the wellbore over time comprises producing fluids from one
subterranean zone and then forming apertures to access a second
subterranean zone.
7. The method of claim 6, comprising sealing apertures providing
fluid communication from the first mentioned subterranean zone to
the wellbore.
8. The method of claim 1, wherein a wall of the wellbore comprises
a casing and wherein sealing apertures of the wellbore comprises
sealing apertures in the casing.
9. The method of claim 1, wherein a wall of the wellbore is an open
hole and sealing apertures of the wellbore comprises sealing an
aperture in a side surface of the open hole.
10. A method of producing fluids from a well, the well having an
existing production profile and a specified production profile and
the existing production profile does not match specified production
profile, the method comprising: receiving location information on
apertures selected to achieve the specified production profile;
operating a laser tool in a wellbore of the well to change a flow
distribution of the wellbore to cause the existing production
profile to more closely match the specified production profile;
wherein operating the laser tool to change the flow distribution in
the wellbore comprises sealing apertures in the wellbore using the
laser; wherein a wall of the wellbore comprises a casing and
wherein sealing apertures of the wellbore comprises sealing
apertures in the casing.
11. A method of producing fluids from a well, the well having an
existing production profile and a specified production profile and
the existing production profile does not match specified production
profile, the method comprising: receiving location information on
apertures selected to achieve the specified production profile;
operating a laser tool in a wellbore of the well to change a flow
distribution of the wellbore to cause the existing production
profile to more closely match the specified production profile;
wherein operating the laser tool to change the flow distribution in
the wellbore comprises sealing apertures in the wellbore using the
laser; wherein a wall of the wellbore is an open hole and sealing
apertures of the wellbore comprises sealing an aperture in a side
surface of the open hole.
Description
TECHNICAL FIELD
The present disclosure relates generally to stimulating and
completing a well in an earth formation, and more specifically, to
systems and methods for stimulation, sand control, perforation,
well completion, drilling operations, and near wellbore
operations.
BACKGROUND
Once a wellbore has been drilled and one or more zones of interest
have been reached, a well casing is run into the wellbore and is
set in place by injecting cement or other material into the annulus
between the casing and the wellbore. The casing, cement and
formation are then perforated to enable flow of fluid from the
formation into the interior of the casing.
In the past, the casing, cement and formation have been perforated
using bullets or shaped charges. Both techniques, however, may
result in a perforation having a positive skin, i.e. localized
decreased permeability that reduces the production of formation
fluid from the formation into the perforation. It is generally
desirable that the perforations have a neutral or a negative skin,
i.e. localized increased permeability resulting in an increased
production of formation fluid. In addition, these traditional
perforating methods rely on the use of explosives, which pose
obvious safety, transportation and security issues.
Known perforating techniques, as well as drilling techniques, do
not provide any analysis of the formation rock being perforated or
drilled. More so, there is no known technique for analyzing the
chemical elements and certain other chemical characteristics of
formation rock in situ, that is, without removing the rock from the
well. Such analysis would be helpful in determining the optimal
location and depth for the current and other perforations, provide
in-situ formation evaluation at the perforation site, or on a
larger scale, assist in evaluating the current well or other wells.
Presently, to obtain an analysis of the formation rock being
perforated or drilled, a representative sample of the formation
rock must be retrieved to the surface and analyzed. Depending on
whether the analysis can be performed on site, such analysis may
add days or even weeks to the well completion. Further, the
analysis involves material that may have been altered in the
process of removing it from the well.
SUMMARY
The present disclosure is drawn to systems and methods of
stimulating and/or perforating that use a laser beam to remove
material, such as to perforate the casing, cement and formation.
The system and method can further or alternately encompass material
analysis that can be performed without removing the material from
the wellbore. The analysis can be performed apart from or in
connection with stimulation operations and/or perforating the
casing, cement and formation.
In some implementations, methods can include: characterizing a
subterranean formation; selecting an orientation of an aperture
based on characteristics of the subterranean formation; and using a
laser to form an aperture of the selected orientation in the wall
of the wellbore. In some implementations, methods can include:
characterizing a subterranean formation; selecting an aperture
shape based on characteristics of the subterranean formation; and
using a laser to form an aperture of the selected shape in a wall
of the wellbore. In some implementations, methods can include:
selecting an orientation of an aperture based on characteristics of
the subterranean formation; and using a laser to form an aperture
in the selected orientation in the wall of the wellbore.
Embodiments of these implementations can include one or more of the
following features.
In some embodiments, selecting an orientation can include selecting
an orientation aligned to provide greater exposure of the aperture
to an axis of preferred permeability. Selecting an orientation can
include selecting an orientation aligned relative to direction of
principal stress in the formation. Selecting an orientation can
also include selecting an orientation to facilitate formation of a
fracture that connects with a natural fracture.
In some embodiments, using the laser to form an aperture can
include forming an aperture connecting to a pre-existing natural
fracture identified while characterizing the formation. Using the
laser to form an aperture can include forming apertures at a
location selected for fracture initiation. Forming apertures can
include forming a aperture that extends along the length of the
wellbore and is orthogonal to a formation bedding plane. Forming an
aperture can include forming a aperture with a first dimension that
increases with increasing distance from an axis of the wellbore.
Using the laser to form an aperture can include forming an aperture
with negative skin.
In some embodiments, the wall of the wellbore can include a casing
and wherein using a laser to form an aperture in a wall of the
wellbore can include forming an aperture in the casing. Using a
laser to form an aperture in a wall of the wellbore can include
forming an aperture extending through the casing into the
subterranean formation. In some embodiments, the wall of the
wellbore can be an open hole and using a laser to form an aperture
in the wall of the wellbore can include forming an aperture in side
surfaces of the open hole.
In some embodiments, characterizing a subterranean formation can
include characterizing a distribution of sizes of particles in the
subterranean formation; and selecting an aperture shape based on
characteristics of the subterranean formation can include selecting
a slot size to filter particles from fluid in the formation, the
slot size selected based on the distribution of sizes of particles
in the subterranean formation.
In some embodiments, methods can include: selecting an aperture
shape based on characteristics of the subterranean formation; and
using a laser to form an aperture of the selected shape in a wall
of the wellbore. Selecting an aperture shape based on
characteristics of the subterranean formation can include selecting
a slot size to filter particles from fluid in the formation, the
slot size selected based on the distribution of sizes of particles
in the subterranean formation.
In some embodiments, the shapes of the apertures have a maximum
dimension that is aligned with a principal stress field of the
formation. Selecting the aperture shape can include selecting an
aperture shape with a longer axis aligned to expose more of the
producing formation than a circular cross-section hole of a similar
perimeter.
In some implementations, methods of producing fluids from a
wellbore can include: communicating fluids through a first aperture
in a wall of the wellbore; and after communicating fluids through
the first aperture in the wall of the wellbore, using a laser to
seal the first aperture in the wall of the wellbore. Embodiments
can include one or more of the following features.
In some embodiments, methods can include, after communicating
fluids through the first aperture in the wall of the wellbore,
using a laser to form a second aperture in the wall of the
wellbore. Communicating fluids through the first aperture in the
wall of the wellbore can include producing fluids through the first
aperture in the wall of the wellbore. Communicating fluids through
the first aperture in the wall of the wellbore can include
introducing fluids into a subterranean zone from the wellbore
through the first aperture in the wall of the wellbore. Methods can
include producing fluids through the second aperture in the wall of
the wellbore.
In some embodiments, the wall of the wellbore can include a casing
and using the laser to seal the first aperture in a wall of the
wellbore can include sealing an aperture in the casing. Sealing the
aperture in the casing can include fusing shut apertures in the
casing. Fusing shut an aperture in the casing can include heating
the casing such that opposite sides of the aperture fuse together
or can include selectively laser sintering fusible powders.
In some embodiments, the wall of the wellbore is an open hole and
using a laser to seal an aperture in the wall of the wellbore can
include sealing an aperture in side surfaces of the open hole.
In some implementations, methods of producing fluids from a well
having an existing production profile and a specified production
profile can include: if the existing production profile does not
match specified production profile, receiving location information
on apertures selected to achieve the specified production profile;
running a laser tool into a wellbore of the well; and operating the
laser tool to change a flow distribution of the wellbore to cause
the existing production profile to more closely match the specified
production profile. Embodiments can include one or more of the
following features.
In some embodiments, operating the laser tool to change the flow
distribution of the wellbore can include forming apertures in the
wellbore using the laser and/or sealing apertures in the wellbore
using the laser. Changing the flow distribution of the wellbore can
include balancing flow along a substantially horizontal wellbore by
changing the distribution of apertures along a substantially
horizontal wellbore.
In some embodiments, changing the production profile of the
wellbore over time can include producing fluids from one
subterranean zone and then forming apertures to access a second
subterranean zone. Methods can include sealing apertures providing
fluid communication from the first subterranean zone to the
wellbore.
In some embodiments, a wall of the wellbore can include a casing
and sealing apertures of the wellbore can include sealing apertures
in the casing. A wall of the wellbore can be an open hole and
sealing apertures of the wellbore can include sealing an aperture
in a side surfaces of the open hole.
In some embodiments, forming apertures in the wellbore using the
laser can include selecting an aperture geometry to filter solids
from fluid in the formation (e.g., a slot with a slot size selected
based on a distribution of sizes of particles in the subterranean
formation; and using a laser to form slots with the selected
aperture geometry in a casing installed in the wellbore in the
subterranean zone. Selecting the aperture geometry to filter
particles from fluid in the formation can include selecting the
aperture geometry to control sand production including formation
fines.
In some implementations, methods of forming a well in a
subterranean formation can include: selecting an aperture geometry
to filter solids from fluid in the formation, the aperture geometry
selected based on a distribution of sizes of particles in the
subterranean formation; and using a laser to form slots with the
selected aperture geometry in a casing installed in the wellbore in
the subterranean zone. In some implementations, methods can
include: selecting a slot size of apertures to control sand
production including formation fines in fluid in a formation, the
slot size selected based on a distribution of sizes of particles in
the subterranean zone; and using a laser to form apertures with the
selected slot size in a casing installed in a wellbore in the
subterranean zone. In some implementations, methods can include:
selecting an aperture geometry to filter solids from fluid in the
formation, the aperture geometry selected based on a distribution
of sizes of particles in the subterranean formation; using a laser
to form slots with the selected aperture geometry in a casing
installed in the wellbore in the subterranean formation; and
producing fluid from the subterranean formation through wellbore.
Embodiments can include one or more of the following features.
In some embodiments, selecting the aperture geometry to filter
solids from fluid in the formation can include selecting an
aperture geometry to filter particles from fluid in the formation.
Selecting the aperture geometry to filter particles from fluid in
the formation can include selecting the aperture geometry to
control sand production including formation fines. in particular,
selecting an aperture geometry to filter particles from fluid in
the formation can include selecting the aperture geometry in which
the cross-section of individual apertures in the casing decrease
with increasing distance from a central axis of the casing such
that a smallest portion of each aperture is at the outer surface of
the casing.
In some embodiments, the subterranean zone can include an
unconsolidated formation and selecting the aperture geometry to
filter solids from fluid in the formation can include selecting an
aperture geometry to maintain structural stability of the
unconsolidated formation.
In some embodiments, method can also include, in response to levels
of particles in fluid being produced through the wellbore,
operating the laser to change a flow distribution of the wellbore.
Operating the laser tool to change the flow distribution of the
wellbore can include forming apertures in the wellbore using the
laser and/or sealing apertures in the wellbore using the laser.
Methods can also include sealing first apertures extending through
the casing and forming second apertures extending through the
casing of the wellbore, the second apertures having a different
geometry than the first apertures. In some cases, a width of the
second apertures is smaller than a width of the first
apertures.
In some embodiments, selecting the slot size of apertures to
control sand production including formation fines in fluid in the
subterranean zone can include selecting an aperture geometry in
which the cross-section of individual apertures in the casing
decrease with increasing distance from a central axis of the casing
such that a smallest portion of each aperture is at the outer
surface of the casing. In some cases, the subterranean zone can
include an unconsolidated formation and selecting the slot size of
the apertures to control sand production including formation fines
in fluid in the formation can include selecting an aperture
geometry and distribution to maintain structural stability of the
unconsolidated formation.
In some implementations, methods of installing downhole equipment
in a wellbore can include: forming a profile in a wall of the
wellbore using a laser; inserting a piece of downhole equipment
into the wellbore such that a portion of the piece of downhole
equipment is aligned with the profile formed in the wall of the
wellbore; engaging the profile formed in the wall of the wellbore
with the piece of downhole equipment. In some implementations,
methods of installing downhole equipment in a wellbore can include:
using a laser to form a recess in an inner surface of a casing
installed in the wellbore; inserting a piece of downhole equipment
into the wellbore; and deploying an extendable dog on the piece of
downhole equipment to matingly engage the recess in the inner
surface of a casing of the wellbore. In some implementations,
methods can include: using a laser to form a window extending
through a casing installed in a wellbore; inserting a piece of
downhole equipment into the wellbore; and engaging the window
formed in the wall of the wellbore with the piece of downhole
equipment. Embodiments can include one or more of the following
features.
In some embodiments, forming the profile can include forming a
female profile in the wall of the wellbore. Forming the female
profile in the wall of the wellbore can include forming a recess in
a casing installed in the wellbore. Forming the recess in the
casing installed in the wellbore can include forming a recess that
only extends partway through the casing. In some cases, the female
profile is sized and positioned to receive extendable dogs on the
piece of downhole equipment.
In some embodiments, forming the female profile can include forming
an annular recess extending around an inner diameter of the casing.
In some embodiments, forming the female profile can include forming
multiple discrete recesses formed at a common distance from an
entrance of the wellbore.
In some embodiments, the piece of downhole equipment is a seal, a
pump, liner hanger, or a downhole steam generator.
In some embodiments, methods can include inserting the piece of
downhole equipment into the wellbore such that the extendable dogs
on the piece of downhole equipment are aligned with the recesses in
the surfaces of the wellbore; and extending the extendable dogs on
the specific piece of downhole equipment to matingly engage the
recesses in the surfaces of the wellbore.
In some embodiments, forming the profile can include forming a
window extending through a casing installed in the wellbore. In
some cases, the window is sized to receive a junction. Methods can
include deploying the junction into the wellbore such that the
junction is aligned with the window; and inserting the junction
into and extending through the window. In some cases, methods can
include sealing the window after inserting the junction into and
extending through the window.
In some embodiments, electric wirelines incorporating downhole
lasers can be used in place of or in addition to conventional
methods of setting and/or unsetting downhole tools such as
setting/unsetting with weight, setting/unsetting using
tubular-supplied hydraulics, or setting/setting with wireline
through the use of explosives. Similarly, in some embodiments,
electric wirelines incorporating downhole lasers can be used in
place of or in addition to conventional methods of freeing stuck
downhole tools such as using tubulars in a fishing operation or
drilling to remove the tools. The use of electric wireline with a
downhole laser for these operations can be faster and often more
precise. Other electric wireline tools can be combined with the
laser to provide data telemetry, retrieval or setting heads, depth
correlation, and electric controls.
An advantage of some of the implementations is that they may enable
at least one chemical characteristic of an earth formation to be
determined without removing the formation or the analysis tool from
the wellbore. Therefore, chemical analysis can be performed during
a single trip of the drilling string, tubing string or wireline
into the wellbore. Multiple locations (both axially and
circumferentially) in the wellbore can be analyzed during the same
trip. In the case of drilling or perforating, the analysis can be
performed without having to remove the drilling or perforating
equipment, and the analysis can be performed concurrently with the
drilling or perforating processes. Such concurrent analysis enables
more frequent sampling of the formation, as well as, more ready use
of the formation information in drilling or perforating.
An advantage of some of the implementations is that material can be
removed or analyzed in two or more locations substantially
concurrently.
An advantage of some of the implementations is that material can be
removed or heated in specified patterns, for example,
circumferential grooves or conical perforations.
An advantage of some of the implementations is that increased
permeability (negative skin) develops in the formation in the area
of the material removed.
An advantage of some of the implementations is that perforations
may be made without the use of explosives.
An advantage of some implementations is that techniques based on
the use of electric wirelines with downhole lasers can remove the
requirement for explosives to be shipped to location and run into
the hole. These techniques can also reduce the likelihood that
sensitive tools such as pressure sensors and other data gathering
sensors are damaged during, for example, tool setting using
explosives. In addition, these techniques can provide the ability
to run and retrieve downhole tools with electric line with very
accurate depth correlation.
An advantage of some implementations is that downhole lasers can be
used to glaze or resurface surfaces downhole. In some instances,
after extended periods of hydrocarbon production, this can provide
a new method of remediating pitting, erosion or other damage that
can occur in the surfaces of downhole tools due to incompatibility
between the flow constituents of production flow stream and the
type of metallurgy used to make the downhole hardware and/or due to
other reasons. Being able to glaze/resurface devices downhole can
save considerable expense (work-over rig costs and non-producing
time) and get the wells to return to production more quickly.
An advantage of some implementations is that lasers can be used to
cut windows for lateral completions including multilateral
completions. Laser cutting of casing may provide improved lateral
windows as compared to milling of windows for lateral
completions.
In some implementations, laser glazing operations can provide
improvements to a metal surface such as hardening of the metal
surface, smoothing the metal surface, decreasing the friction
coefficient of the surface, and increasing corrosion resistance of
the metal surface. Laser glazing, particularly in downhole
applications, can provide much higher efficiency than chemical
treatments used to try and achieve at least some of the same
effects. For downhole oilfield operations, the metal surface
improvements provided by laser glazing may enhance multi-lateral
milling, drilling, and completion operations. In addition,
production equipment may be more cost effectively treated to allow
continued production without equipment replacement.
In some implementations, the combination of downhole laser tools
and associated downhole video and/or thermal imaging cameras can
provide highly efficient devices for freeing tools which are stuck
downhole. Normally, impediments to stuck tools downhole require
fishing operations with tubulars. These tubulars often encounter
difficulty engaging the top of the tools or difficulty freeing the
tools once engaged. Downhole video has been used to define the
obstruction or configuration of the top of the tool. This requires
a separate trip into the wellbore for the video, then customized
drilling or fishing devices are run in on tubulars to remove the
impediment or reconfigure the top of the tool to allow for proper
fishing tool engagement. Much of this work is trial and error and
may require several trips with the video camera. By combining laser
with the video and/or thermal imaging operation the impediments can
be removed in a single trip.
In some implementations, downhole laser tools and operations can be
used to remove and/or consolidate formation material downhole to
control the degree of communication from the wellbore to the
formation. Consolidation may also be achieved or enhanced by
selective laser sintering of heat-fusible solids unto the wellbore
surfaces. Selective laser sintering may be carried out by
depositing a layer of a heat-fusible powder onto surface.
Heat-fusible powders include ceramics, metals, and plastic polymers
such as ABS plastic, polyvinyl chloride (PVC), polycarbonate, and
other polymers. The laser beam heats the powder and sinters the
particles into a solid surface. A second layer of powder may be
deposited on the sintered surface and again treated with the laser.
In this manner, the sintered surface may be built up layer by
layer. In some cases, a single sintered layer may be sufficient to
form a sufficiently consolidated surface. In addition, certain
filter cake formulations may be applied to the wellbore surface
during drilling operations. Laser irradiation may be used to
further enhance the filter cake such that the wellbore surface is
consolidated. These consolidation processes can reduce the amount
of fines produced over time. As the same laser can be used to form
perforations in the formation, both perforation and formation
treatment can be performed in one downhole trip instead of the
multiple trips for perforation and formation treatment required
today.
Forming perforations using downhole laser tools and methods is
compatible with many wireline tools; can be used to provide
precision perforations (e.g., clean and highly precise cuts in
terms of length, width and depth) on previously installed casing;
and can be used in conjunction with technology such as gamma ray
logging, casing collar location and/or other technology. This
approach can achieve more precise placement and sizing of
perforations than explosive shape charge perforating and
hydrajetting. Moreover, this approach does not induce compaction
damage to the target rock.
In some implementations, lasers can be used to initiate explosives,
such as those used in explosive-based perforating guns used in
perforating wellbore casings and/or subterranean formations and/or
in other operations. Since a laser is used to detonate the
explosives, there is no possibility of electrical interference.
Only firing of the laser will fire the explosives. No radio silence
or other restrictions on the use of electrical equipment during
perforating operations are required. This can provide increased
safety for personnel onsite as well as reduced chances of
accidentally perforating out of zone due to electrical
interference. In addition, the elimination of electrical
interference issues opens the possibility of combining adding
electric conductors to the fiber in the wireline cable so that one
can run logging tools during perforating runs. This may enable a
savings in rig time due to the ability to combine logging and
perforating in a single run.
The details of one or more embodiments of the invention are set
forth in the accompanying drawings and the description below. Other
features, objects, and advantages of the invention will be apparent
from the description and drawings, and from the claims.
DESCRIPTION OF DRAWINGS
FIG. 1 is a schematic of downhole tool system.
FIG. 2 is a side cross-sectional view of an illustrative laser tool
depending from a wireline and depicted perforating a wellbore.
FIG. 3 is a side cross-sectional view of an illustrative laser tool
depending from a tubing string and depicted perforating a
wellbore.
FIG. 4 is a schematic of a downhole tool system with a
wireline.
FIG. 5 is a schematic of a downhole tool system with a coiled
tubing string.
FIG. 6A is a side cross-sectional view of the illustrative laser
tool of FIG. 2 showing different trajectories of the laser
beam.
FIG. 6B is a cross-sectional view of FIG. 6A along section line B-B
showing different trajectories of the laser beam.
FIG. 6C is a cross-sectional view of an alternate illustrative
laser tool showing different trajectories of the laser beam typical
in drilling a vertical wellbore.
FIG. 6D is a cross-section view of another alternate illustrative
laser tool showing different trajectories of the laser beam
achieved using a fiber optic array.
FIGS. 7A-7I is a series of side cross-sectional views illustrating
the sequence of a laser-initiated treatment process.
FIGS. 8A-8C is a series of side cross-sectional views illustrating
a portion of the sequence of a laser-initiated treatment
process.
FIGS. 9A and 9B are schematics of a laser set packer.
FIGS. 10A and 10B are schematics of a laser released packer.
FIGS. 11A-11C is a series of schematic side views illustrating a
downhole laser-glazing process.
FIG. 12 is a schematic view of a laser-initiated detonation.
FIGS. 13A and 13B are, respectively, an axial cross-sectional
schematic and a transverse cross-sectional schematic of a liner
hanger in a wellbore.
FIG. 14 is a schematic of a junction in a wellbore.
Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
Downhole laser tools and techniques can be used to enhance
communication between a wellbore and a subterranean formation, to
provide adequate flow paths, to reduce potential fluid flow
restriction due to formation damage, to allow for more precise
design for radial flow into or out of a formation, and to implement
stimulation treatments for enhancing fluid flow such as acidizing,
sand control or hydraulic fracturing treatments. Downhole laser
tools can be deployed, for example, with wireline or tubing (coiled
and/or jointed) and is compatible with wellbore configurations
without internal diameter restrictions. Perforation techniques can
be used to create specific size or geometry for opening(s), from
large holes or slots to allow solids such as proppant particles to
enter easily, to narrow slots in casing that would allow
significant fluid flow into or out of the wellbore while preventing
production of solids such as formation sand and proppant. The
perforation techniques may be combined with high pressure pumping
to create a larger opening and/or to stimulate the formation. For
example, laser operations may be performed to perforate and/or
initiate a fracture in concert with high pressure pumping
operations.
Downhole laser tools and techniques also can be used other
applications. For example, downhole laser tools and techniques can
be used to treat the surface of downhole equipment in situ; to set
and release downhole equipment; to consolidate formation material;
and to initiate explosives, such as those used in perforating
wellbore casings and/or subterranean formations.
Once a wellbore has been drilled into a formation and casing is set
inside the wellbore, communication between the formation and the
interior of the well casing is through openings (i.e.,
perforations) created through the casing and (if present) cement
filling the annulus between casing and the formation. The
perforations may be through the casing material only, also through
an annular fill (such as cement) and stop at formation face, or
they may penetrate to some depth into the formation. The
perforations may be in the form of approximately circular
perforations, elongated slots and/or other shapes.
Referring to FIG. 1, an illustrative downhole tool system 200 for
use in a wellbore 10 includes a laser source 29 on the surface, a
deployment system 210 (spooled, cable, coiled tubing, jointed pipe,
etc.), and a laser tool 20. The deployment system 210 can include
an umbilical 27 (e.g., cable or tubing (coiled or jointed) with
cable on the inner diameter) that, for example, contains optical
fibers and/or other waveguide elements used to controllably
transmit light from the surface to the laser tool 20. A laser beam
26 (e.g., a high intensity laser beam) can be transmitted from the
laser source 29 via a transmission line 27 (e.g., a wireline
containing an optical fiber) to the laser tool 20. The downhole
tool system 200 can include a mechanism for achieving proper
orientation in the wellbore relative to formation properties or
other geometric consideration such as depth or direction and/or
extendable stabilizers such as those discussed in more detail in
U.S. Pat. Pub. No. 2006/0102343, incorporated herein by reference.
The downhole tool system 200 can also include an anchoring system
(e.g., slips, collets, and/or matching profiles in the tool system
200 and surrounding tubular, such as the casing) for fixing the
laser tool 20 in position in the wellbore 10. After the laser tool
20 is temporarily anchored in the wellbore 10, an on-board system
such as those discussed in more detail below for moving and
adjusting the position of and characteristics of the laser beam can
precisely control the characteristics of the directed laser beam 26
such as, for example, the position, cutting depth, and impingement
angle. This system can allow very specific and precise entry into
the formation from the wellbore to be achieved. In some instances,
the laser source 29 can be provided wholly or partially
downhole.
Referring to FIGS. 2 and 3, the wellbore 10 is illustrated as a
cased wellbore in a formation 12 that has a casing 14 affixed
therein. A layer of cement or similar material 16 fills an annulus
between the casing 14 and the wellbore 10. An embodiment of the
laser tool 20 is depicted in use perforating the wellbore 10. The
illustrative laser tool 20 is adapted to be inserted into the
wellbore 10 depending from a wireline 18 (FIGS. 2 and 4) or a
tubing string 19 (FIGS. 3 and 5), and to direct the laser beam 26.
Although depicted as removing material from the formation 12 to
form a perforation 22, the laser tool 20 can be adapted to also or
alternatively drill a new wellbore or extend an existing wellbore.
As discussed in more detail in U.S. Pat. Pub. No. 2006/0102343,
incorporated herein by reference in its entirety, the laser tool
can also be adapted to heat material to emit light for use in laser
induced breakdown spectroscopy (LIBS). In addition, a
non-destructive laser spectroscopic methods may be used, optionally
in combination with drilling and/or stimulation operations, to
interrogate formation properties by spectroscopic analysis of the
reflected light.
As the illustrative laser tool 20 of FIGS. 2 and 3 is depicted
perforating a cased wellbore 10, it is directing the laser beam 26
onto the casing 14, the cement 16, and the formation 12. The
illustrative laser tool 20 and related concepts described herein
are equally applicable to an "open hole" wellbore. An open hole
wellbore is one in which at least a portion of the wellbore has no
casing. Furthermore, the laser tool 20 may be used in perforating
or drilling through various equipment installed in a wellbore, and
is not limited to perforating through casing, cement layers, and
formation. When referring to a wall of a wellbore herein, the wall
can include any interior surface in the wellbore, such as a
sidewall or end/bottom wall thereof.
The downhole deployment system 210 can include of a spool 212 for
the umbilical (e.g., wireline 18 in FIG. 4 or coiled tubing string
19 in FIG. 5). In some embodiments, as shown in FIGS. 4 and 5, such
laser sources 29 can be small enough to mount on the inner surface
of the spool 212 holding the wireline 18 or coiled tubing string
19. Mounting the laser in the spool eliminates the need for rotary
optical couplers connecting the cable on the spool to the laser
because the laser source 29 moves with rotation of the spool
212.
In some embodiments, the laser tool 20 and cable can be carried
down hole by a mobile device such as for example, a wireline
deployed self-propelled robotic device (e.g., well tractor), rather
than on tubing or the cable alone. This technique may have
advantages in horizontal or highly deviated wells. In this
approach, the tractor acts as the slips to anchor the tool in
position and rather than moving the tool with a hydraulic section,
the tractor can controllable move the laser tool 20 when extending
an initial perforation. For example, long, continuous slots can be
formed by activating the laser tool 20 while the well tractor moves
the laser tool 20 along the well bore.
Power and/or signals may be communicated between the surface and
the laser tool 20. Wireline 18 may include one or more electrical
conductors which may convey electrical power and/or communication
signals. Wireline 18 may additionally or alternatively include one
or more optical fibers which may convey light (e.g. laser) power,
optical spectra, and/or optical communication signals. Neither the
communication of power, nor signals to/from the surface, are
necessary for the operation of the implementations. In lieu of such
communication, downhole batteries and/or downhole generators may be
used to supply the laser tool 20 power. A downhole processor may be
employed to control the laser tool 20, with relatively little (as
compared to wireline) or no communication from the surface. For
example, instructions for performing operations may be
preprogrammed into a processor installed in the laser tool 20
before running the laser tool 20 into the wellbore 10 and/or the
laser tool 20 may respond to simple commands conveyed via surface
operations such as rotary on/off, relatively low data rate
mud-pulse, electromagnetic telemetry, and acoustic telemetry
communication.
In implementations incorporating a tubing string 19, the tubing may
be continuous tubing or jointed pipe and may be a drilling string.
The tubing string 19 may incorporate a wireline 18 as described
above. Tubing string 19 may be "wired drill pipe," i.e. a tubing
having communication and power pathways incorporated therein, such
as the wired drill pipe sold under the trademark Intellipipe by
Grant Prideco, Inc. The tubing string 19 may contain a smaller
tubing string within for conveying fluids such as those used in the
fluid based light path described below or for conveying chemicals
used by the laser.
In addition to waveguides to transmit laser light from the surface
to downhole, the umbilical may also contain optical fibers and
sensors to measure the temperature distribution of the umbilical
along its length. These measurements can be used to detect hot
spots where the umbilical may be damaged and deteriorating as a
result of damage. By identifying damaged or abnormally hot sections
of the umbilical, a potentially dangerous umbilical breach or
umbilical failure may be avoided. Additionally under normal
operations, it would be desirable to know the temperature
distribution of the umbilical in order to help insure that the
umbilical is operated only under specified conditions which can to
help provide a long service life.
The laser tool 20 can also include other features such as, for
example, an extendable light path and/or a snorkel as described in
more detail in U.S. Pat. Pub. No. 2006/0102343.
The laser tool 20 can control the timing, direction, focus and
power of the laser beam 26. Different light patterns can be applied
by varying the timing (i.e. pulsing), direction, focus, and power
of the laser beam 26 depending on the type of materials to be
removed, treated, or analyzed, for example, the casing 14, the
cement 16 and different types of rock in the formation 12.
Accordingly, in removing material, the laser beam 26 light patterns
can be adjusted to crack, spall, melt, or vaporize the materials to
be removed and change as the material type changes. The laser beam
26 can be configured to remove material in a single continuous
pulse or multiple pulses. The multiple pulses may be cyclical, such
as in a duty cycle. The power of the laser beam 26 can be selected
such that the duty cycle necessary to remove the material in the
desired manner (crack, spall, melt or vaporize) is less than 100%.
In most instances of removing material during perforating
operations, the laser beam 26 is directed on the formation with a
duty cycle that causes the rock to chip or spall. Laser beam/tool
configurations including pulse strategies are discussed in more
detail in U.S. Pat. Pub. No. 2006/0102343.
In FIGS. 2 and 3, the illustrative laser tool 20 includes a laser
beam device 24. The laser tool 20 may optionally be provided with a
focusing array 28 through which the laser beam 26 passes.
Additional details regarding focusing arrays and their operation
are discussed in more detail in U.S. Pat. Pub. No.
2006/0102343.
The laser beam device 24 may relay the laser beam 26 generated
remotely from the laser tool 20, such as generated by a laser
source 29 on the surface and input into the laser beam device 24
via a transmission line 27 (FIG. 3), such as an optical fiber or
light path. In some embodiments, rather than relaying a laser beam
generated at the surface, the laser beam device 24 generates the
laser beam 26. In such embodiments, the laser beam device 24 may
be, for example, an electrical, electro-chemical laser or chemical
laser, such as a diode laser or an excimer or pulsed Na:YAG laser,
dye laser, CO laser, CO.sub.2 laser, fiber laser, chemical oxygen
iodine laser (COIL), or electric discharge oxygen iodine laser
(DOIL). In some implementations it may be desirable to use a DOIL
to increase service intervals of the laser tool 20, because a DOIL
does not substantially consume the chemicals used in creating the
laser beam and the chemicals need not be replenished for an
extended duration. It is to be understood that the examples of
particular lasers disclosed herein are for illustrative purposes
and not meant to limit the scope of the claims.
Additionally, the laser tool 20 can include hydraulic channels
running through the laser tool 20 so that fluid pumped around the
cable can pass through the laser tool 20. Such fluid can provide a
liquid purge for maintaining a relatively clean light path from the
laser tool 20 to the formation, can help remove debris and cuttings
produced by the action of the laser, and can cool the laser tool
20. In an embodiment, a gas and a liquid purge may be used in
combination to remove debris and cuttings produced by the laser. By
way of example, referring to FIG. 3, window 54 may be modified such
the window may be opened to form an aperture. Optionally the
aperture may be fitted with an extension channel fitted to the
outer wall of laser tool 20. Gas may be pumped down the tubing
string 19 to provide a clear path for the laser beam 26. At the
same time, a liquid purge may be pumped down the annular space
between the tubing string 19 and the casing 14 to remove debris and
cuttings. In some embodiments, the laser tool 20 can be made to
rotate along its longitudinal axis to move the beam in an arc or
circle around the wellbore.
Some or all of the components of the laser tool 20 can be encased
in a housing 52. The housing 52 can have one or more windows 54
adapted to allow passage of the laser beam 26 out of the housing 52
and emitted light 36 into the housing 52. The size and shape of the
windows 54 accommodate the aiming capabilities of the laser beam 26
and receipt of emitted light 36. The windows 54 are further adapted
to withstand the elevated pressures and temperatures experienced in
the wellbore 10. Some examples of materials for constructing the
windows 54 may be glass, silica, sapphire, or numerous other
materials with appropriate optical and strength properties. The
windows 54 may have anti-reflection coatings applied to one or both
surfaces to maximize the transmission of optical power therethrough
while minimizing reflections. The windows 54 may comprise a
plurality of optical fibers positioned to direct the laser beam 26
or collect emitted light 36 from multiple locations about the
wellbore 10. For example the optical fibers may be fanned radially
about the laser tool 20.
Although the laser beam device 24 can be oriented to fire directly
towards the material being removed or heated in one or more
trajectories, the illustrative laser tool 20 is configured with the
laser beam device 24 firing into a reflector 30. The reflector 30
directs the laser beam 26 toward the formation 12 and may be
operated to assist in focusing the laser beam 26 or operate alone
in (when no focusing array 28 is provided) focusing the laser beam
26 into the material being removed. In the illustrative laser tool
20 of FIGS. 2 and 3, the laser beam 26 is directed substantially
longitudinally through the laser tool 20 and the reflector 30
directs the laser beam 26 substantially laterally into the wellbore
10. The laser tool 20 can be configured to fire the laser beam 26
in other directions, for example, down.
The laser beam 26 may be directed to remove material or heat
various points around the wellbore 10 and in varying patterns. In
an illustrative laser tool 20 having a reflector 30, the reflector
30 can be movable in one or more directions of movement by a
remotely controlled servo 32 to control the direction, i.e.
trajectory, of the reflected laser beam 26. In a laser tool where
the laser beam device 24 fires directly into the formation 12 or in
a laser tool having a reflector 30, the laser beam device 24 can be
movable by control servo to control the trajectory of the laser. In
lieu of or in combination with a reflector 30, the laser beam can
be directed into the formation 12 using a light path (see FIG. 6D,
discussed below), such as a fiber optic, that may optionally be
movable by control servo to control the trajectory of the laser
beam. The light path may include multiple paths, such as a fiber
optic array, that each direct the laser beam in a different
trajectory. The multiple paths can be used selectively,
individually or in multiples, to direct the laser beam in different
trajectories.
In the illustrative example of FIGS. 2 and 3, the laser beam 26 is
directed using the reflector 30 and control servo 32, rather than
or in combination with moving the laser tool 20. The control servo
32 can be configured to move the reflector 30, at least one of,
about a longitudinal axis of the wellbore 10 (see FIG. 6A), about a
transverse axis of the wellbore 10 (see FIG. 6B), or along at least
one of the longitudinal and transverse axis of the wellbore 10.
FIG. 6A depicts the laser tool 20 firing the laser beam 26 through
angle .alpha. about the wellbore longitudinal axis. Depending on
the application, it may be desirable to configure the laser tool 20
so that angle .alpha. may be as much as 360.degree.. FIG. 6B
depicts the laser tool 20 firing the laser beam 26 through angle
.beta. about the wellbore transverse axis. Depending on the
application, it may be desirable to configure the laser tool 20 so
that angle .beta. may be as much as 360.degree.. The laser tool 20
can be appropriately configured so as not to fire the laser beam 26
upon itself. FIG. 6C depicts an illustrative laser tool 20 firing
in multiple trajectories, through angle .phi., typical for drilling
a vertical wellbore 10. Depending on the application, angle .phi.
may be as much as 360.degree. and may be oriented through
360.degree. polar about the longitudinal axis of the laser tool
20.
FIG. 6D depicts a illustrative laser tool 20 that uses a light path
104 comprised of multiple optical fibers 106 each oriented to fire
in a different trajectory. The laser beam 26 may be directed
through all of the multiple optical fibers 106 substantially
simultaneously, or may be multiplexed through the multiple optical
fibers 106, for example, as a function of duty cycle as is
described below. Likewise, emitted light can be received through
the multiple optical fibers 106 for use in material analysis as is
described herein. Although depicted with a specified number of
optical fibers 106 arranged vertically, the number and pattern of
the optical fibers 106 can vary. For example, only one optical
fiber 106 can be provided. In another example, the pattern in which
the optical fibers 106 are arranged can additionally or
alternatively extend circumferentially about the laser tool 20 to
reach circumferential positions about the wellbore 10. The
arrangement of optical fibers 106 can be configured to produce
specified patterns in the material removed, heated, and/or
analyzed.
By directing the laser beam 26 relative to the laser tool 20, with
reflector 30, light path 104, or otherwise, the laser tool 20 can
remain in a single position (without further adjustments or
reorientation) and remove or heat material in multiple locations
around the wellbore 10. Accordingly, the number of adjustments
and/or orientations of the laser tool 20 during an entire operation
is reduced. Physically moving the laser tool 20 is time-consuming
relative to adjustment of the laser trajectory using the
configurations described herein (ex. by moving reflector 30).
Therefore, the ability to reach multiple trajectories without
moving the laser tool 20 reduces the amount of time necessary to
perform operations (drilling, perforating, formation analysis,
stimulating).
According to the concepts described herein, the laser beam 26 can
be manipulated with multiple degrees of freedom and focal points to
remove material in many different patterns. For example, standard
geophysical investigation techniques can be used in characterizing
a subterranean formation to observe formation characteristics such
as permeability, principle directions of stress, the size
distribution of particles in the formation, and/or formation
fracturing characteristics. The orientation and/or shape of the
aperture(s) in the wall of a wellbore can be selected based on
characteristics of the subterranean formation.
The orientation of the aperture(s) can be selected with an
alignment to provide greater exposure of the aperture(s) and/or
induced fracture(s) initiated at the aperture(s) to an axis of
preferred permeability. So for example, a slice or thin wedge can
be removed from the wall of the wellbore 10, orthogonal to and
along the length of the wellbore 10, and orthogonal to a formation
bedding plane, with a larger thickness at its distal end from the
wellbore 10, and exposing far more formation surface than
traditional perforating operations.
Aperture shapes and orientations can be selected based on the
location of natural fractures in the formation. For example,
apertures can be formed connecting to a pre-existing natural
fracture identified while characterizing the formation. In some
cases, an orientation of the apertures can be selected to
facilitate formation of a fracture that connects with a natural
fracture. The laser can be used to form apertures at a locations
selected for fracture initiation. In some cases, the orientation of
the apertures can be selected with an orientation aligned relative
to direction of principal stress in the formation. The orientation
of the apertures can be parallel to, orthogonal to, or at a
specific angle relative to the direction of principal stress in the
formation. The shapes of the apertures can have a maximum dimension
that is aligned relative to a principal stress field of the
formation. Selecting the aperture shape can include selecting an
aperture shape with a longer axis aligned to expose more of the
producing formation than a circular cross-section hole of a similar
perimeter.
The distribution of sizes of particles in the subterranean
formation can also be an used in selecting the shape and size of
apertures being formed in a wellbore. For example, in a sandy
formation, aperture shapes can be selected as slots with a slot
size chosen such the slots being formed in a well casing filter
particles from fluid in the formation. Larger apertures may be
selected in a coal seam where the casing is used to prevent
formation collapse rather than to filter out fine particles from
fluid being produced from the formation.
The concepts described herein enable a perforation hole to be
shaped (such as by providing slots, rather than tubes or pits) to
minimize fluid pressure down-draw. Multiple shapes can be
envisioned within the implementations which may promote hydrocarbon
recovery rate, total recovery and efficiency.
In the illustrative laser tool 20, the laser beam 26 can be
directed to remove or heat material circumferentially about the
wellbore 10 by actuating the control servo 32 to rotate the
reflector 30 about a longitudinal axis of the wellbore 10 and/or
actuating the reflector 30 to move along the transverse axis of the
wellbore 10. The laser beam 26 can be directed to remove or heat
material along the axis of the wellbore 10 by actuating the control
servo 32 to rotate the reflector 30 about a transverse axis of the
wellbore 10 or move along the longitudinal axis of the wellbore 10.
The laser beam 26 can be directed to remove or heat material in an
area that is larger than could be removed in a single trajectory,
by actuating the reflector 30 to rotate about and/or translate
along at least two axes, for example the longitudinal and
transverse axis. The laser beam 26 would then be directed in two or
more different trajectories to substantially adjacent locations on
the material being heated or removed. For example, by directing the
laser beam 26 to project on the material being removed or heated at
quadrants of a circle, the laser beam 26 can substantially remove
or heat the material in a circular shape. By directing the laser
beam 26 in two or more trajectories at the same location, the laser
tool 20 can remove material to form a conical perforation having a
largest diameter at the opening or having a smallest diameter at
the opening. Also, the laser beam 26 may be directed in one or more
trajectories to form a perforation in the earth formation, and
concurrently while forming the perforation or subsequently, be
directed in one or more trajectories to widen the perforation. The
laser beam 26 can also be directed in two or more different
trajectories to remove or heat material of the earth formation in a
substantially continuous area or two or more disparate areas.
The laser being directable can be also be use to drill more
efficiently and/or with unique hole characteristics, as compared to
both the classic drill-bit drilling and prior non-directable laser
drilling. In drilling with the laser beam 26, the laser beam 26
would be directed axially rather than radially, and the laser beam
tool 20 would be conveyed on the bottom of the bottom hole assembly
in place of the drilling bit (see FIG. 6C). A circular path could
be swept by the laser beam 26, cutting (for example by spalling) a
thin annular hole, approximately equal to a desired hole diameter.
The resulting "core" sticking up in the middle would be
periodically broken off and reverse circulated up the wellbore 10,
for example up the middle of the drill string 19, to the surface.
Accordingly, the laser energy is being used only to cut a small
amount of rock (i.e. the annular hole). The same laser beam 26
directing configurations discussed above in the context of
perforating could be applied to drilling. Because the material
removal is not resulting from a mechanical bit being rotated, a
circular cross-section hole is not necessary. For example, the
laser beam 26 could be directed to sweep out elliptical, square, or
other hole shapes of interest.
Using the directionality of the material removal allows formation
of specified perforation section shape(s) that can provide enhanced
production. For example, the perforations can be formed in a
rectangular, oval, elliptical, or other hole section with a longer
axis aligned to expose more of the producing formation than a
circular cross-section hole, or aligned to provide greater exposure
to an axis of preferred permeability, or preferential production
(or non-production) of oil, water, gas, or sand. In another
example, aperture geometry can be selected based on a distribution
of sizes of particles in the subterranean formation to filter
solids from fluid in the formation, the aperture geometry. Solids
can range in size. The solids can be large pieces such as discrete
chunks fractured from the body of a coal seam and small particles
such as sand and formation fines. In some instances, the
cross-section of individual openings in the casing can decrease
with increasing distance from a central axis of the casing such
that the smallest portion of each opening is at the outer surface
of the casing. In unconsolidated formations, the aperture geometry
and distribution can be selected to maintain structural stability
of the unconsolidated formation.
Such specified perforation section shape(s) may provide wellbore or
perforation stability. For example, a rectangular, oval, or
elliptical shape can be employed with a longer axis aligned with
the principal stress field of the formation, for increased
stability and reduced tendency of collapse as compared to a
circular cross-section hole. Moreover, if the formation rock is
stable, the openings may be cut deeply into the formation, thus
creating negative skin (enhanced flow potential) and enhancing
formation fluid production or fluid injection.
In some well designs, evenly distributed openings arranged around
the circumference of the wellbore can be formed by either removing
all casing material for some width or by leaving some casing
material in place. These openings can be repeated across the height
of the formation or along the length of the wellbore if the
wellbore is not vertical. This scenario works very well for a
formation that is fairly isotropic with no immediate plan to use
hydraulic fracture stimulation.
If the formation is to be hydraulically fractured, the openings
could be created in a desired direction with respect to formation
rock stresses, such as in the direction of the maximum stress. The
openings can be sized to allow the desired flow of proppant laden
fluid (unrestricted, or with a specific desired degree of slurry
flow restriction). Using lasers to etch deep into the formation can
significantly lower the pressure required for formation breakdown
and also can lower the fracture propagation pressure.
If the formation is known to be anisotropic or naturally fractured,
the location of the openings may be designed to take advantage of
the formation properties or specific geomechanics present. For
example, stress anisotropy is defined as a condition existing in a
formation where there is a higher stress in one direction. In rock
mechanics, these stresses are given three dimensions--x-y referring
to the horizontal directions at 90 degrees orientation and the z
direction in the vertical orientation.
For a conventional perforated well, Pb=3.sigma.h-.sigma.H+Tensile
strength of the rock where Pb is the breakdown pressure (i.e., the
pressure necessary to initiate a fracture in rock by applying
hydraulic force; .sigma.h is the minimum horizontal stress; and
.sigma.H is the maximum horizontal stress. For a laser perforation
with a perforation tunnel length of six times the wellbore radius
Pb=.sigma.h+Tensile strength of the rock For a laser slotted
perforation configuration, where the effective area of the
perforation tunnel is increased substantially with a six inch
penetration into the rock and a six inch vertical penetration:
Pb=.sigma.h+Tensile strength of the rock Thus, laser perforations
in general can result in a lower pressure necessary to initiate a
fracture in rock by increasing the area of rock exposed to the
hydraulic force such that the hydraulic pressure X perforation area
equals the force applied to the rock to initiate the fracture.
In addition, the ability to precisely locate perforations being
formed by laser tools can make it easier to locate openings to
coincide with the higher permeability areas of the formation.
Since, for a laser perforation that is oriented in such a way to
connect to an exposed pre-existing natural fracture as determined
by logging information: Pb=.sigma.h This can further reduce the
pressure necessary to initiate a fracture in rock. Various logging,
seismic, and/or micro-seismic techniques such as, for example,
triple combo logging based on a combination of resistivity, bulk
density, and porosity measurements; magnetic resonance imaging; and
dipole sonic logging can be used to locate exposed pre-existing
natural fractures. The laser tool 20 is then positioned to form
perforations accessing these natural fractures.
In wellbores that are not cased, or cased but have no annular fill
for sealing material, laser cuts that penetrate the formation can
create a "zone of weakness" at the selected location to enhance the
probability that fracture initiation from a frac treatment would
occur at the selected location(s), whereas conventional shape
charge perforating methods may actually increase resistance to
fracture initiation by the severe compaction of the formation
material that occurs using that perforation process. Additionally,
lasers can be used to create or fuse shut slotted liner sections
"in-situ". Selective laser sintering of fusible powders may also be
used to close slotted liner section `in-situ". One advantage of
doing this is that slotted liner sections can be created
selectively after standard casing has been run and cased hole logs
used to determine where liner slots should be placed. This would
eliminate the need for intricate space-out of liner sections while
deploying the liner.
In some instances, the general sequence of laser initiation of a
stimulation/fracturing treatment proceeds as illustrated in FIGS.
7A-7J. A section of wellbore to be stimulated is illustrated in
FIG. 7A. The downhole tool 214 including slips 216 and packer 218
is run in the hole on a jointed pipe (see FIG. 7B) before the laser
tool 20 is run downhole on the cable and landed and sealed in the
downhole tool (see FIG. 7C). Next, the slips 216 are set as shown
in FIG. 7D. In some cases, the slips 216 of the downhole tool 214
can be set prior to running the laser tool 20. The laser light
(denoted as the dotted arrows) is transmitted down the cable,
collimated or focused, and directed toward the formation with a
reflector 30 (see FIG. 7E). As described above with reference to
FIG. 6A, the reflector 30 may be movable in order to control the
direction of the beam.
Additionally, fluid can be pumped from the surface along the cable,
through channels in the laser tool 20 and outward, coaxially with
the laser energy. The stream of fluid can provide several
advantages. First, the fluid can move debris and other materials
removed by the laser away from the beam. Second, the fluid can help
maintain a clear, low optical loss path between the laser tool 20
and the inner surface of the wellbore. Finally, the flow of fluids
from the surface can cool the laser tool 20 and the cable.
In general, the fluid is chosen for its optical clarity so as to
minimize the disruption of the focused laser beam. The efficiency
of a fluid-based light path is a function of the optical
transmission efficiency of the fluid. To increase the efficiency of
the fluid-based light path, a fluid having a high optical
transmission efficiency at the wavelength of the laser beam 26 or
emitted light 36 can be selected. Water, certain oils, and mixtures
or solutions including water and/or oil, are among many efficient
optically transmissive fluids that can be used for the fluid-based
light path. While water and oil are both liquids, the fluid need
not be liquid. For example, the fluid-based light path could be a
gas, such as nitrogen at high pressure. The absorptivity of the
fluid for the laser and LIBS Spectrum wavelengths should be taken
into account during the selection of the fluid used in the light
path. In an embodiment, a gas such as nitrogen at high pressure may
be used with a liquid to allow a clear path for the laser beam.
The density of the fluid, as well as the speed at which it is
expelled from the laser tool 20, may be selected to reduce the
influence of outside factors on the path of the fluid-based light
path. For example, as the drilling mud circulates through the
wellbore 10, it can entrain the fluid-based light path, and, in the
case of a light path that is directed substantially perpendicular
to the wall of the wellbore 10, shift the light path to impact the
wall at an angle and at a different location that originally aimed.
Likewise, impacts with larger particulate in the drilling mud may
attenuate or deflect the light path from its trajectory. Such
deflection and shift can be reduced by jetting the fluid at a high
speed or even ultrasonic speed and/or by choosing a fluid that is
dense. The density of the fluid, be it water, oil, or other, can be
increased, if so desired, with a weighting agent, such as cesium
salt, which can result in a mixture which has acceptable
transparency. Additionally, the circulation of fluids through the
wellbore 10 can be ceased during operation of the laser tool 20, or
the laser tool 20 can be operated when circulation of fluids would
otherwise be ceased, for example, while adding joints of pipe in
the normal drilling process.
The influence of outside factors on the path of the fluid-based
light path can also be reduced by reducing the distance the light
path must span between the laser tool 20 and the material being
removed or analyzed. The distance can be reduced by providing the
outlet through which the fluid-based light path is expelled close
to the material being removed or heated, for example, by selection
of the laser tool 20 diameter to be close to the diameter of the
wellbore 10 and/or provision of the outlet in a stabilizer fin. To
the degree the fluid based light path does shift or deflect, if the
light path remains continuous or any break in the light path is
insignificant, the laser beam 26 or emitted light 36 will still
follow the path and be transmitted between the material being
removed or analyzed and the laser tool 20.
However, for subterranean wellbores, the medium within the wellbore
provides functions such as, for example, well control, bit
lubrication, pipe lubrication, sloughing control, cuttings
transport and removal, temperature regulation, pressure regulation
and other specialized functions. As optical clarity is not a
typically requirement for wellbore media, a majority of traditional
wellbore fluids (i.e., drilling muds) do not readily transmit light
and are inappropriate for the downhole laser applications. However,
other medium which normally have been used in specialized
applications (both on surface and in the subsurface) are candidates
for this application. Some fluids useful for this purpose include,
for example, fresh water, inorganic salt brines, or soluble
viscosifiers. Acids (e.g., acetic acid, hydrochloric acid, formic
acid, citric acid or combinations thereof); gases (e.g., nitrogen,
natural gas, and carbon dioxide), and oils (e.g., mineral oil,
gasoline, xylene, and toluene) can also be used.
For example, some saltwaters including but not limited to sodium
chloride, potassium chloride, ammonium chloride, calcium chloride,
sodium bromide, calcium bromide, zinc bromide, potassium formate,
and cesium formate saltwaters can have a level of light
transmissibility that can permit the transmission of a laser beam
in a subterranean environment. These saltwaters span the density
range from 8.3 ppg to 22 ppg. The density range is important in
that as the density of fluid impacts the hydrostatic pressure used
for well control (i.e., to balance the subterranean pressure from
the different strata). It can be advantageous use fresh water and
some saltwaters because these fluids can be left in the wellbore
and/or formation after use.
In another example, a variety of viscosifing agents can also
provide a clear medium for transmission of light. Specific examples
of agents that provide a clear medium for transmission of light
include but are not limited to polysaccharide-hydroxyethyl
cellulose (HEC) (commercially available as Halliburton Product
WG-17), carboxymethyl hydroxypropyl guar (CMHPG) (commercially
available as Halliburton Product WG-18), hydroxypropyl guar (HPG)
(commercially available as Halliburton Product WG-11), biopolymers
such as xanthan (commercially available as Halliburton Product
WG-24, WG-37, and BP-10) and diutan, and derivatized HEC
(commercially available as Halliburton Product WG-33). Examples of
agents that, properly prepared and/or filtered can provide a clear
medium for transmission of light include but are not limited to
Terpolymer (commercially available as Halliburton Product
FDP-S906-08) and guar gum (commercially available as Halliburton
Product WG-11, WG-19, WG-22, WG-26, WG-31, WG-35, WG-36). In some
embodiments, the fluid may absorb the laser energy and vaporize to
provide a clear path for the laser beam. Vaporization of the liquid
along the laser beam path may assist in removal of debris and
cuttings from the actions of the laser. Minimizing the fluid path
length of the laser beam, for example, by extendable devices may be
advantageous in the use of liquid fluids to remove debris and
cuttings.
The viscosifing agents can suspend and "sweep" away residual drill
cuttings which could otherwise block the transmission of the laser
beam. These agents can also increase the viscosity of the fluid in
the wellbore which can help limit the loss of fluid (leak off) to
the formation and can help to maintain a constant and consistent
subterranean environment. In addition, because most of these fluids
can be used with a variety of saltwaters, they can provide a wide
range of densities which make them more useful for well control
applications.
Carbon Dioxide is a gas at standard temperatures and pressures.
When it reaches its super critical state (87.9.degree. F.
(31.1.degree. C.) and 1070.6 psia (7.38 mpa)), carbon dioxide acts
as both a liquid and a gas and, as a colorless liquid, can have
good light transmission properties.
Acids are often used in subterranean environments for their
abilities to dissolve and remove unwanted materials or objects.
Acids which can have sufficient light transmissivity to be used
with downhole laser tools include but are not limited to HCl, HF,
acetic, citric, and formic Acids. Acid solutions can also provide a
reactive medium to assist in the operation of the laser to produce
the desired material removal effects.
Certain petroleum distillates can provide a high level of optical
clarity which would permit the operation and transmission of a
laser beam. Petroleum distillates include but are not limited to
xylenes, butanes, etholenes, tolulenes, propane, terpine and
various other fluids. Certain products like propane would typically
be gaseous but under pressure and temperature constraints can be
made into a liquid. These liquids are often beneficial as
solvents.
Laser tools 20 using fluid-based light paths are discussed in more
detail in U.S. Pat. Pub. No. 2006/0102343.
After the laser has been on, an initial perforation 22 is made as
shown in FIG. 7E. In order to extend the perforation 22, the
hydraulic system in the downhole tool 214 moves the laser tool 20
vertically relative to the stationary slips 216 at a controlled
rate. This motion while the laser is on extends the perforation 22
into a slot as shown in FIG. 7F.
At this point, it may be possible to reposition the downhole tool
214 without removing the laser tool 20 and repeat the steps shown
in FIGS. 7D-7F to make multiple slots without withdrawing the laser
tool 20 to the surface. However, if the downhole tool 214 is run on
jointed pipe, one will only be able to move the downhole tool 214
with the laser tool 20 in place the length of the pipe joint. If
joints need to be added or removed from the string, the laser tool
20 will need to be retrieved to surface before adding or removing
joints and run back in to continue cutting.
The laser tool 20 can be withdrawn to the surface (see FIG. 7G)
before the packers 218 are set (see FIG. 7H), and the stimulation
treatment commenced (see FIG. 7I). In some cases, the packer(s) 218
will not be required for stimulation and the downhole tool may be
removed and the stimulation treatment pumped from the surface.
Referring to FIGS. 8A-8C, in some embodiments, the downhole tool
214 and laser tool 20 are combined on the end of coiled tubing such
that one can make multiple cuts over a wide range of depths by
repeatedly performing the illustrated steps and repositioning the
coiled tubing between iterations. After the perforations are
formed, the coiled tubing can be removed and the stimulation
treatment can be pumped downhole. Alternatively, the coiled tubing
can be left in place and the treatment pumped downhole outside of
the coiled tubing. Additionally, the addition of a bypass valve in
the coiled tubing string that routes stimulation fluids around the
laser tool (e.g., routing flow from the bore of the coiled tubing
into the annulus and/or otherwise bypassing the laser tool) can
allow one to pump the stimulation fluids through the coiled tubing
with the downhole tool 214 and laser tool 20 and cable in place.
Thus, in some instances, hydraulic fracturing operations conducted
on multiple interval completions can take advantage of laser
perforating deployed with coiled tubing or wireline to conduct the
fracturing operations sequentially without the need to trip in and
out of the wellbore between treatments to perform the perforating
operations.
If the laser tool 20 is mounted on the end of a coiled tubing unit,
it can be run in the well and the laser and purge fluid can impinge
on a fixed location to effect a simple, round perforation. The
laser tool 20 can be rotated in the well bore if desired to make
multiple round, azimuthally distributed perforations at a single
depth. The coiled tubing mounted laser tool 20 can then be
repositioned to perforate at a different depth. Simple laser
perforating can be accomplished with the cable conveyed laser tool
20 and downhole tool.
In another application, laser tools can be used to activate setting
and releasing mechanisms in downhole tools apart from or together
with weight, tension, or explosives. The tools can be conveyed into
position by wireline or jointed or coiled tubing and then set in
place by using a downhole laser tool. For example, a downhole laser
can be used to heat fluid in a sealed chamber to provide hydraulic
force necessary to activate the setting or unsetting mechanism in
the tool. In another example, a downhole laser can be used to cut
an element to release stored energy provided by a spring mechanism
within the tool. Similarly, the same technique can be used to
provide a release mechanism for retrieving these tools. Use of
these techniques to set and/or release tools provides operations
that do not require explosives or specially run tubulars. In
addition, if sensitive tools (such as pressure gauges, fluid
sensors, etc.) need to be placed precisely in a wellbore, the use
of laser activated tools provides a `softer` set mechanism as well
as compatibility with other wireline tool components that provide
depth correlation and telemetry for data retrieval.
In some embodiments, a laser can be generated at the surface and
conveyed through a fiber-optic cable (e.g., as part of an electric
wireline cable) to a pressure vessel attached to a downhole tool.
The laser can be used to heat fluid in the pressure vessel to
provide hydraulic force capable of shifting a tool to a set or
unset position for the purpose of setting or retrieving the tool
with wireline.
FIGS. 9A and 9B illustrate use of this technique to set a packer
218. The packer 218 is run into the well with the slips 216 and
sealing elements 220 retracted. Once the packer 218 is located at
the desired depth, a laser tool 20 is lower into the well to a
position adjacent to a fluid filled chamber 222 in the packer tool.
The fluid in the chamber 222 expands and exhibits increased
pressure when heated sufficiently. The laser beam heats the fluid
in the chamber caused fluid expansion and increased volume. The
pressure is transferred through a floating piston 224 to another
chamber 226 which contains a hydraulic oil. The hydraulic oil
passes through a check valve 228 and acts upon a hydraulic ram 230
which compresses a sealing element 220. The sealing element 220
transfers the axial load to the slip loading ram 232 which drives
the slips 216 out against the casing. The packer remains set
because the check valve 228 prevents the hydraulic oil from flowing
back into the oil chamber 226 once the laser beam is removed an the
expansive fluid cools down. This concept can be used with any tool
which required actuation downhole. For example, other common tools
that can be set or released using this technique include, for
example, bridge plugs, and anchors for sensors such as pressure,
rate, temperature, micro-seismic, and/or tilt-meters; `kick-off`
plugs, oriented re-entry ports for multi-laterals, and baffles.
In some embodiments, the laser can be used in conjunction with
settable tools to cut elements within the tool to release springs
or other resilient members that would provide the stored energy to
activate the setting mechanism and disengage the wireline from the
set tools. Alternatively, when tools require retrieval the laser
can cut through a retaining mechanism within the tool that would
allow removal of the tool with wireline.
FIGS. 10A and 10B show a laser released packer. In this embodiment,
a mechanical element which maintains the integrity of the packer
set is removed with a laser thus causing the packer to become
unset. A laser tool is lowered into the wellbore until it is
properly aligned with the release element 234 within the packer.
The release element holds the mechanical load placed on the setting
mandrel 230 during setting of the packer 218. This load is carried
by the setting mandrel 230, the sealing element 220, the slip ram
232, and the slips 216 which "bite" into the casing. The laser beam
is then turned on and the release elements 234 are removed causing
the mechanical load on the packer to be relieved, thus allowing the
packer to un-set. This type of release mechanism can be used on any
tool which has a secondary position which is held in place by a
mechanical element. This same method can be used to initiate a set
or other downhole tool movement by releasing a spring or opening a
hydraulic path which causes a change in position in a downhole
tool.
In another application, downhole lasers can be used to glaze or
resurface surfaces downhole. In some instances, the glazing can be
performed after extended periods of hydrocarbon production.
For example, in some instances, the production flow stream contains
solids that pit or erode a surface (e.g., a surface of a downhole
tool). If the chemical nature of the flow constituents is unknown
or not properly planned for, the flow-wetted surfaces may begin to
deteriorate very quickly due to incompatibility between the flow
constituents and the type of metallurgy used to make the downhole
hardware. Being able to glaze/resurface the necessary downhole
devices in place can save considerable expense (work-over rig costs
and non-producing time) and get the wells to return to production
more quickly.
Certain wells require stimulation to produce at economic rates. The
stimulation treatments can be performed at any time during the life
of the well. It is not uncommon for wells to receive multiple
stimulations over the course of a number of years. The fluids and
components of the stimulation systems can be erosive, corrosive, or
both. Downhole laser tools can be used to perform downhole glazing
to repair damage created from the stimulation fluids placed into
the wellbore and/or damage that may have occurred when the remnants
of the stimulation fluids flow back through the flow-wetted parts
of the downhole installation.
Laser glazing of metal surfaces is a process in which the surface
of a metal is heated by laser irradiation. As the laser beam passes
over the surface, a micro-surface layer of the metal can be melted.
Once the laser beam moves, the melted micro surface layer can
quickly re-solidify into a thin surface coating. This surface
coating hardens the surface and may remove stress cracking (e.g.,
stress cracking that may be involved in the initiation of metal
failure). In addition, the surface of a metal that has been treated
by laser glazing often has a lower coefficient of friction than the
original untreated surface.
Using downhole laser glazing can provide a hardened, smoothed, and
more lubricious metal surface and, performed in a downhole
environment, has a number of advantageous applications. For
example, the laser glazing of the metal surfaces adjacent to/in
proximity to lateral wellbores from a vertical wellbore (i.e., the
"bend" or "heel" section of a deviated or lateral wellbore)
provides advantages in horizontal drilling, completions, or
work-over operations. In particular, multi-lateral drilling and
completion operations may be enhanced by metal surface treatments
that provide results achievable by laser glazing; especially
following an operation such as milling a window in casing.
Additionally, such laser glazing may also enhance metal resistance
to corrosion.
In subterranean wellbores, horizontal drilling and horizontal
completions sometimes require lateral milling through the casing of
a wellbore to allow the subsequent drilling and completion of a
lateral from that wellbore. For example, this may occur in cases
where the primary wellbore is vertical, inclined, or horizontal in
nature. In a typical window milling operation, a casing whipstock
is set and used to guide a casing milling tool. After the casing
milling operations are complete, the milling tools are removed and,
in some cases, a drilling whipstock can then be placed for guidance
of the drilling operation through the milled window. In the
drilling of the lateral, the initial angle of deviation is
typically on the order of 5 to 10 degrees. However, even with these
small angles of deviation, drilling collars may rub and wear on the
casing sections above the milled window and hardening of this area
can reduce wear. Thus, it is desirable that material at the
junction is relatively soft for easier milling operations.
Subsequently hardening and smoothing this area can reduce wear
during subsequent drilling and completion operations when the
milled window is being utilized.
Referring to FIGS. 11A-11C, laser glazing can be used in lateral
milling, drilling, and completion operations. For example, as shown
in FIG. 11A, a window can be milled through the casing of a
wellbore 10. Although illustrated as a vertical wellbore, the
wellbore 10 can be inclined or horizontal in nature. After window
236 has been milled through the casing of the wellbore 10, a
downhole laser tool 20 can be used to glaze interior surfaces of
the casing of the well bore for a distance D1 above the window 236
as shown in FIG. 11B. The downhole laser can be deployed on
wireline or (coiled and/or jointed) tubing. The distance D1 can be
approximately 100 feet (e.g., more than 25 feet, more than 50 feet,
more than 75 feet, less than 200 feet, less than 150 feet, and/or
less than 125 feet). The downhole laser tool 20 can then be
withdrawn from the well bore 10 and lateral well bore drilled
through the window 236. The downhole laser tool 20 can then be
deployed into the lateral well bore to glaze a casing of the
lateral well bore for a distance D2. The distance D2 can be
approximately 20 feet (e.g., more than 5 feet, more than 10 feet,
more than 15 feet, less than 50 feet, less than 40 feet, and/or
less than 30 feet). Laser glazing of the casing about 100 feet
above the junction and glazing of the lateral stinger provides
hardened surfaces with reduced wear and friction such that lateral
drilling and completion operations are enhanced.
Referring to FIG. 11B, laser-formed coatings such as ceramic,
polymer, metal, or other coatings may be applied to the inner
surfaces of the casing for distance D1 wherein D1 can be
approximately 100 feet (e.g., more than 25 feet, more than 50 feet,
more than 75 feet, less than 200 feet, less than 150 feet, and/or
less than 125 feet). Referring to FIG. 11C, laser-formed coatings
such as ceramic, polymer, metal, or other coatings by be applied to
the inner surfaces of the casing for distance D2 wherein D2 can be
approximately 20 feet (e.g., more than 5 feet, more than 10 feet,
more than 15 feet, less than 50 feet, less than 40 feet, and/or
less than 30 feet). Such laser-formed coating may be applied by
selective laser sintering of fusible-powders.
In some instances, the laser tool can be used to form the window
extending through a casing installed in a wellbore. After the
window is formed, a piece of downhole equipment can be inserted
into the wellbore; and engaged to the window. For example, the
laser can be used to form a window sized to receive a junction. The
junction is then deployed into the wellbore such that the junction
is aligned with the window; and inserted into and extending through
the window. The window can be sealed after the junction is inserted
into and extending through the window. FIG. 14 illustrates a
junction inserted in a window formed in a casing in a wellbore.
Typically subterranean wellbores are designed to be functional for
multiple years and decades. The wellbore hardware is constructed
based on the anticipated future flow of fluids (e.g., oil and
water), gas (e.g., natural gas), and occasionally solids (e.g.,
sand and/or formation materials). However, should there be a
significant change to the flow constituents, the flow nature and
characteristics may exceed the original design parameters of the
downhole hardware. Examples of production changes that can
negatively impact downhole hardware include: increasing solids
content leading to increasing erosion and pitting; the introduction
of sulfide reducing bacteria (SRB) into the reservoir which can
turn the product sour and cause the steel of the hardware to crack;
and increasing water flow creating scale deposition. When this
occurs, the normal process has been to mobilize a rig, attempt to
remove the existing downhole hardware and replace it with more
appropriate hardware
This process can be a very expensive series of operations. There is
a significant risk that well will not be able to return to the same
level of production after the replacement is complete. In addition,
the removal of the existing downhole hardware may be very difficult
and time consuming, and it may not be possible to physically remove
the hardware. Downhole laser glazing can be used to change the
surface characteristics of the flow-wetted downhole hardware (e.g.,
production packers, mandrels, gas lift mandrels, sand control
screens, control valves, sliding sleeves, and production tubing) to
provide new characteristics intended to be more appropriate to the
new flow regime.
Normal well operations such as setting packers and perforating can
also cause surface damage and increased susceptibility to corrosion
and erosion in high wear areas within a well casing. Each time a
packer or other downhole tool is "set" in the casing, biting action
of the slips can damage the casing. The same sections of a casing
(e.g., a section near a perforation through the casing) are often
used repeatedly for setting packers and/or other downhole tools. In
time, such high-use sections of the casing become very worn and
damaged. Laser glazing can be used to enhance these
high-wear/high-use areas and/or to smooth and repair these
areas.
In addition, selective laser sintering of fusible-powders (metal,
ceramic, polymer, or fusible powders) can be used to modify,
build-up, or repair the surfaces of downhold hardware and/or
casing.
Additionally, laser glazing/treatment following perforation of
casing can smooth and harden the surface of the perforated casing
and holes to reduce erosion and corrosion in the areas damaged
during perforation.
Laser glazing operations can provide improvements to a metal
surface such as hardening of the metal surface, smoothing the metal
surface, decreasing the friction coefficient of the surface, and
increasing corrosion resistance of the metal surface. Laser
glazing, particularly in downhole applications, can provide much
higher efficiency than chemical treatments used to try and achieve
at least some of the same effects. As noted above, for downhole
oilfield operations, the metal surface improvements provided by
laser glazing may enhance multi-lateral milling, drilling, and
completion operations. In addition, production equipment may be
more cost effectively treated to allow continued production without
equipment replacement.
Downhole laser operations can also be used in combination with
downhole video and/or thermal imaging camera observation of the
laser operations. For example, downhole lasers and video can be
used in combination to remove impediments to downhole tools. A
laser generated at the surface can be conveyed downhole to a
moveable targeting device through a fiber optic cable embedded into
a electric line cable. The same cable can also include a fiber
optic cable for the purpose of providing downhole video capability
with a camera at the end of the cable in juxtaposition to the laser
targeting device. Thus, the operator would have surface control of
laser cutting at a remote, downhole location. In regions where
video camera images may be impeded, thermal imaging cameras may be
used to guide laser operations. Thermal imaging sensors may also be
used in combination with video cameras to evaluate laser cutting or
welding operations to assist in control of the laser beam (power,
direction, and other laser operational parameters.
Downhole laser tools and operations can also be used to control the
degree of communication from the wellbore to the formation (e.g., a
downhole laser tool can be used to remove and/or consolidate
formation material downhole). For example, a laser may be used
downhole to remove and/or consolidate formation material. The laser
can have variable power levels to achieve varying effects. The
laser might be used to consolidate the wellbore to enhance borehole
stability and, in effect, make an in-situ casing. A low power
setting might be used to perforate a subterranean formation and
then a high power setting might be used to consolidate the interior
of the perforation tunnel. Varying power settings, durations, and
sequences can be used to vary the properties of the consolidated
rock from completely impermeable to very permeable. Other
combinations of power, duration, sequences, and transmission
materials can be used to change the structure of the consolidated
formation in the range from vitrified to crystalline.
Materials might be used downhole prior to, during, or after the
laser treatment to further modify or enhance the properties of the
consolidated rock such as strength or permeability. For example, a
filter cake may be created by pressure pumping below fracturing
rates. When exposed to the laser, the filter cake can be solidified
to enhance the mechanical strength of the rock. In another example,
a material (e.g., a fusible ceramic particulate) can be added to a
liquid transmission medium which would interact with the
consolidation process such that the permeability of the
consolidated rock was changed. This consolidation process can
reduce the amount of fines produced over time. As the same laser
can be used to form perforations in the formation, both perforation
and formation treatment can be performed in one downhole trip
instead of the multiple trips for perforation and formation
treatment required today.
In another downhole application on of laser technology, lasers can
be used to initiate explosives, including explosives of
explosive-based perforating guns for perforating wellbore casings
and/or subterranean formations. Traditionally, wireline conveyed
explosives are electrically initiated. This mature technology is
susceptible to EM and other radio or electrical interference which
may cause the explosives to fire prematurely, sometimes with
catastrophic results.
Referring to FIG. 12, a laser detonator includes an optical fiber
240 in the logging cable. This fiber 240 is capable of transmitting
fairly large amounts of laser power. Light exiting the end of the
fiber is focused through a conventional lens 242 or alternatively,
a curved mirror through a transmissive window 244 to heat a small
volume of temperature sensitive material 246 such as, for example,
titanium subhydride potassium perchlorate (THKP). Heating of the
THKP causes the detonation of an adjacent volume of an explosive
248 such as, for example, high melting explosive (HMX) which is
used to initiate detonating cord 250 connected to a conventional
explosive train to fire the perforating guns.
Since a laser is used to detonate the explosives, there is no
possibility of electrical interference of any sort. Only firing of
the laser will detonate the explosives. No radio silence or other
restrictions on the use of electrical equipment during operations
are required. This can provide increased safety for personnel
onsite as well as reduced chances of accidentally perforating out
of zone due to electrical interference. The elimination of
electrical interference opens the possibility of combining adding
electric conductors to the fiber in the wireline cable so that one
can run logging tools during perforating runs. This may enable a
savings in rig time due to the ability of combining logging and
perforating in a single run.
In some embodiments, a laser can be used to ignite a explosive
propellant for the wireline setting of packers and bridge plugs.
For example, the HMX in FIG. 12 can be replaced with a propellant
that activates a wireline setting tool such as, for example, a
Baker 20 wireline tool. This can be significantly quicker than
heating up a fluid to pressure set a tool as described with respect
to FIGS. 9A and 9B.
In another downhole application on of laser technology, laser tools
can be used to adjust the flow parameters of a well that has been
in production. For example, fluids can be communicated through a
first aperture in a wall of the wellbore. The fluids can be
pressure fluids being used to frac a formation, fluids being
produced from a subterranean formation through the wellbore, and/or
fluids such as steam being introduced into the subterranean
formation from the wellbore.
After communicating fluids through the first aperture in the wall
of the wellbore, a laser can be used to seal the first aperture in
the wall of the wellbore. In some instances, the wall of the
wellbore includes a casing and the laser is used to seal an
aperture in the casing. The aperture can be sealed by fusing shut
apertures in the casing (e.g., by heating the casing such that
opposite sides of the aperture fuse together) or by selectively
laser sintering fusible powders (e.g., fusible powders disposed in
the aperture). In some instances, the wall of the wellbore is an
open hole and using a laser to seal an aperture in the wall of the
wellbore includes sealing an aperture in side surfaces of the open
hole (e.g., by glazing the surface of hole extending into a
subterranean formation to reduce the local permeability of the
formation in the vicinity of the hole). The laser can also be used
to form a second aperture in the wall of the wellbore which can be
used, for example, to producing fluids from the subterranean
formation.
This approach can be applied to heavy oil formations in which it is
desirable to reduce the viscosity of oil in a subterranean
formation. Steam can be introduced into the subterranean formation
through first apertures in the wall of a wellbore. A laser tool can
then be used to seal the first apertures. The laser tool can then
be used to open other apertures in the wall of the wellbore. These
second apertures can be formed, for example, at locations spaced
apart from the locations where the first apertures were previously
found. Alternatively or additionally, these second apertures can be
formed at the same location where the first apertures were
previously found but with a different geometry (e.g., shape and/or
distribution) than the first apertures.
This approach can also be used to adjust the production profile of
a well. For example, a well can having an existing production
profile and a specified production profile. If the existing
production profile does not match specified production profile,
location information on apertures selected to achieve the specified
production profile can be received. A laser tool can be run into a
wellbore of the well and operated to change a flow distribution of
the wellbore to cause the existing production profile to more
closely match the specified production profile. Operating the laser
tool to change the flow distribution of the wellbore can include
forming apertures in the wellbore using the laser and/or sealing
apertures in the wellbore using the laser.
For example, in response to the upcoming of underlying water near
the heel of a horizontal well, apertures near the heel of the
substantially horizontal wellbore can be sealed and additional
apertures can be formed at the far end of the horizontal wellbore.
Thus, the laser tool can be used to change the distribution of
apertures along a substantially horizontal wellbore to balance flow
along the substantially horizontal wellbore.
In another example, after producing fluids from one subterranean
zone, apertures can be formed to access a second subterranean zone.
In some instances, the apertures providing fluid communication from
the first subterranean zone to the wellbore can be sealed.
In another downhole application on of laser technology, laser tools
can be used in the installation of downhole equipment in a
wellbore. The laser can be used to form a profile (e.g., a female
profile) in a wall of the wellbore. A piece of downhole equipment
(e.g., a seal, a pump, liner hanger, or a downhole steam generator)
can be inserted into the wellbore and the profile formed in the
wall of the wellbore can be engaged with the piece of downhole
equipment.
The female profile in the wall of the wellbore can be a recess in a
casing installed in the wellbore (e.g., a recess that only extends
partway through the casing). The female profile can be sized and
positioned to receive extendable dogs on the piece of downhole
equipment. The female profile can include an annular recess
extending around an inner diameter of the casing or multiple
discrete recesses formed at a common distance from an entrance of
the wellbore to set the location of the piece of downhole equipment
along the wellbore. In some instances, the female profile includes
a keyway or multiple keyways to limit the rotation of the piece of
downhole equipment after it is set in place with the extendable
dogs on the piece of downhole equipment are aligned with and
extended to matingly engage the recesses in the surfaces of the
wellbore.
FIGS. 13A and 13B are schematics illustrating the use of a female
profile comprising multiple discrete recesses to suspend a liner
hanger in a wellbore. Although shown as vertical, the wellbore
could have other orientations (e.g., be slanted or horizontal). The
recesses extend only partway through a casing in the wellbore. Four
equally spaced dogs are extended to engage the recesses to hold the
liner hanger in place. Other numbers of recesses and dogs can be
used in other embodiments of the system.
Various configurations of the disclosed systems, devices, and
methods are available and are not meant to be limited only to the
configurations disclosed in this specification. Even though
numerous characteristics and advantages have been set forth in the
foregoing description together with details of illustrative
implementations, the disclosure is illustrative only and changes
may be made within the principle of the invention. Accordingly,
other embodiments are within the scope of the following claims.
* * * * *
References